Adaptability Evaluation of Conformance Control Agents in Low Permeability Reservoirs with Fractures

2014 ◽  
Vol 960-961 ◽  
pp. 170-175
Author(s):  
Feng Lan Zhao ◽  
Shu Jun Cao ◽  
Ji Rui Hou
Keyword(s):  
Graft Copolymer ◽  
Polymer Concentration ◽  
Gelation Time ◽  
Injection Pressure ◽  
Low Permeability ◽  
Particle Type ◽  
Conformance Control ◽  
Fracture Width ◽  
Preformed Particle Gel ◽  
Low Permeability Reservoirs

Several conformance control agents, including preformed particle gel, emulsion microspheres, continuous chromium gel and underground starch graft copolymer gel were evaluated. The properties such as gelation time and gel strength of gel, and expansion of particles and microspheres were tested at high temperature. Also, the injection pressure, plugging strength and resistance factor were measured using the artificial low permeability cores with fractures. It was shown that, for particle type conformance control agents, the particle size should be adaptable with the fracture width. Also, for continuous chromium gel, the added polymer concentration higher, the viscosity is higher, with higher plugging strength. The plugging and strength should be coordinated. The starch graft copolymer gel is easy to be injected into formation and has good plugging property. The results show that underground starch graft gel is more suitable for conformance control in low permeability formation with fractures.

scholarly journals Study on the adaptability of binary flooding in a certain oil field

Open Physics ◽  
2021 ◽  
Vol 19 (1) ◽  
pp. 447-453
Author(s):  
Liping Ma ◽  
Xiaochun Liu ◽  
Qing Yang ◽  
Wei Lu ◽  
Shitou Wang ◽  
...  
Keyword(s):  
Binary System ◽  
Surfactant Concentration ◽  
Polymer Concentration ◽  
Injection Pressure ◽  
Salt Resistance ◽  
Oil Field ◽  
Low Permeability ◽  
Synergistic Mechanism ◽  
Hydrolyzed Polyacrylamide ◽  
Low Permeability Reservoirs

Abstract To explore the synergistic mechanism of polymer and surfactant in the binary combination flooding of low-permeability reservoirs, the adaptability experiment of polymer salt-resistant partially hydrolyzed polyacrylamide and nonionic surfactant was carried out in the indoor system. Experiments at different ratios are also performed. The results show that the selected poly/surface binary flooding system increases with the concentration of polymer or surfactant, the viscosity of the poly/surface binary system also increases and, at the same time, has better temperature and salt resistance. The viscosity of the binary system will decrease when the salinity increases. When the surfactant concentration CS = 0.2% and the polymer concentration CP = 0.2%, the viscosity of the system is the highest. The viscosity of the poly/table binary system at different concentrations decreases when the temperature rises: pure polymer (CP = 0.2%), poly/table binary system displacement fluid CP = 0.1% + CS = 0.2% and CP = 0.2% + CS = 0.2%; and the injection pressure first rises and then drops. The final recovery rate is 51.8%, which meets the development of most oil reservoirs.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 2310-2315 ◽  
Author(s):  
Ming Xian Wang ◽  
Wan Jing Luo ◽  
Jie Ding
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Low Permeability ◽  
Reservoir Permeability ◽  
Engineering Parameters ◽  
The Common ◽  
Common Problems ◽  
Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

pH-Sensitive Polymers for Novel Conformance-Control and Polymer-Flood Applications

2010 ◽  
Vol 13 (06) ◽  
pp. 926-939 ◽  
Author(s):  
Suk Kyoon Choi ◽  
Mukul M. Sharma ◽  
Steven L. Bryant ◽  
Chun Huh
Keyword(s):  
Polymer Solution ◽  
Polymer Concentration ◽  
Injection Pressure ◽  
Low Ph ◽  
Ph Sensitive ◽  
Solution Viscosity ◽  
Conformance Control ◽  
Polymer Flood ◽  
Geochemical Reactions ◽  
Acidic Conditions

Summary Novel conformance-control and polymer-flood applications that exploit the pH sensitivity of partially hydrolyzed polyacrylamide (HPAM) are proposed. The key feature of this process is the injection of the HPAM solution under acidic conditions. The low pH makes polymer molecules coil tightly, resulting in a very low polymer-solution viscosity. This allows the polymer solution to be injected into the reservoir at a substantially reduced injection pressure. Once injected, the acid reacts with the formation minerals to cause a spontaneous pH increase, uncoiling the polymer chains and causing a large increase in solution viscosity. Such a viscosity-control scheme can be exploited for placement of a concentrated polymer solution in high-permeability zones, where it later viscosifies to divert subsequently injected fluids (in-depth conformance control), or to reduce the high pressure drop near the wellbore during polymer injection (injectivity improvement). Extensive laboratory experiments were systematically performed and interpreted to evaluate the novel applications of pH-sensitive HPAM. The evaluations require (a) quantification of steady-shear viscosities, (b) characterization of geochemical reactions with acids, and (c) transport evaluation of HPAM solutions in cores. Rheological measurements show that shear viscosities of HPAM solution have a pronounced, but reversible, dependence on pH. The peak pHs observed in several shut-ins guarantee that spontaneous geochemical reactions can return the polymer solution to its original high viscosity. The use of a weak acid is the key. Coreflood results show that the HPAM solution under acidic conditions can be propagated through cores with much higher mobility than at neutral pH. However, low-pH conditions increase adsorption (polymer loss) and require additional chemical cost (for acid). The optimum injection formulation (polymer concentration, injection pH) will depend on the specific reservoir mineralogy, permeability, salinity, and injection conditions.

scholarly journals Experimental Study on the Effect of ASP Flooding on Improving Oil Recovery in Low Permeability Reservoirs Based on a Partial Quality Tool

Processes ◽  
2020 ◽  
Vol 8 (3) ◽  
pp. 296 ◽  
Author(s):  
Bin Huang ◽  
Xinyu Hu ◽  
Cheng Fu ◽  
Quan Zhou
Keyword(s):  
Molecular Weight ◽  
High Molecular Weight ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Low Permeability ◽  
Displacement Effect ◽  
Oil Displacement ◽  
Matching Degree ◽  
Low Permeability Reservoirs ◽  
Quality Tool

In order to solve the problem of the poor oil displacement effect of high molecular weight alkali/surfactant/polymer (ASP) solution in low permeability reservoirs, Daqing Oilfield uses a partial quality tool to improve the oil displacement effect in low permeability reservoirs. In the formation, the partial quality tool degrades the polymer through active shearing action, reducing the molecular weight of the polymer, to improve the matching degree to the low permeability oil layer and the oil recovery. In order to study the ability of the partial quality tool to improve the oil displacement effect, the matching degree of high molecular weight ASP solution to low permeability cores is studied, and the ability of quality control tools to change the molecular weight is studied. Then, experimental research on the pressure and oil displacement effect of high molecular weight ASP solution before and after the actions of the partial quality tool is carried out. The results show that ASP solutions with molecular weights of 1900 × 104 and 2500 × 104 have a poor oil displacement effect in low permeability reservoirs. After the action of the partial quality tool, the injection pressure is reduced by 5.22 MPa, and the oil recovery is increased by 7.79%. The injection pressure of the ASP solution after shearing by the partial quality tool is lower than that of the ASP solution with the same molecular weight and concentration without shearing, but the oil recovery is lower. On the whole, the use of the partial quality tool can obviously improve the oil displacement effect in low permeability reservoirs.

Preformed-Particle-Gel Extrusion Through Open Conduits During Conformance-Control Treatments

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1083-1093 ◽  
Author(s):  
Abdulmohsin Imqam ◽  
Baojun Bai ◽  
Mustafa Al Ramadan ◽  
Mingzhen Wei ◽  
Mojdeh Delshad ◽  
...  
Keyword(s):  
Particle Size ◽  
Laboratory Data ◽  
Injection Pressure ◽  
Resistance Factor ◽  
Co2 Production ◽  
Conformance Control ◽  
Preformed Particle Gel ◽  
Particle Strength ◽  
Opening Ratio ◽  
Inner Diameter

Summary Millimeter-sized (10 μm–mm) preformed particle gels (PPGs) have been used successfully as conformance-control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solution or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit inner diameter and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle/opening ratio compared to strong gel. PPG strength affected injectivity more significantly than did particle/opening ratio. Resistance factor increased as the brine concentration and conduit inner diameter increased. PPGs can significantly reduce the permeability of a conduit, and their plugging efficiency depends highly on the particle strength and the conduit inner diameter. The particle size of PPGs was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. On the basis of the laboratory data, two correlations were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle/opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle-gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits.

scholarly journals An approach for determining the water injection pressure of low-permeability reservoirs

2018 ◽  
Vol 36 (5) ◽  
pp. 1210-1228 ◽  
Author(s):  
Wenya Lyu ◽  
Lianbo Zeng ◽  
Minzheng Chen ◽  
Dongsheng Qiao ◽  
Jianming Fan ◽  
...  
Keyword(s):  
Ordos Basin ◽  
Water Injection ◽  
Injection Pressure ◽  
Production Performance ◽  
Low Permeability ◽  
Bohai Bay ◽  
Natural Fractures ◽  
Effective Measure ◽  
Water Breakthrough ◽  
Low Permeability Reservoirs

Waterflooding is an important functional process for low-permeability reservoir development. However, production practice shows that water breakthrough and floods along natural fractures are ubiquitous in low-permeability reservoirs. Therefore, controlling the water injection pressure to prevent water breakthrough and floods along natural fractures is an effective measure for improving the waterflooding development effect. In this paper, an approach is proposed for determining the water injection pressure based on the opening pressure of natural fractures in fractured low-permeability reservoirs. The opening pressures of natural fractures calculated by the analytical method in the paper and the formation-parting pressures are compared based on the production performance in two different fault blocks F16 and Z3 of the Zhouqingzhuang Oilfield in the Bohai Bay Basin, China. The results show that the calculated opening pressures of the natural fractures in fault blocks F16 and Z3 are 31.4 and 42.9 MPa, respectively, and they are close to the opening pressures of natural fractures obtained from the step-rate tests in injection wells (28.6 and 41.1 MPa); whereas, the formation-parting pressures (44.5 and 47.6 MPa) are greater than the opening pressures of natural fractures. This suggests that the opening pressures of natural fractures can be used, instead of the formation-parting pressure, for the maximum threshold of the water injection pressure. Its effectiveness has been confirmed via comparison to the production performances of the other two wells in the Zhouqingzhuang Oilfield and several fractured low-permeability reservoirs in the Ordos Basin, China. This study will have beneficial applications in the design of waterflooding development in low-permeability reservoirs characterized by the presence of natural fractures.

ASSESSMENT OF OIL WELL PRODUCTIVITY IN LOW-PERMEABILITY RESERVOIRS IN THE FIELDS OF EASTERN SIBERIA

2017 ◽  
pp. 30-36
Author(s):  
R. V. Urvantsev ◽  
S. E. Cheban
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Oil And Gas ◽  
Oil Extraction ◽  
Low Permeability ◽  
Oil Well ◽  
Eastern Siberia ◽  
Development Costs ◽  
Traditional Fields ◽  
Low Permeability Reservoirs

The 21st century witnessed the development of the oil extraction industry in Russia due to the intensifica- tion of its production at the existing traditional fields of Western Siberia, the Volga region and other oil-extracting regions, and due discovering new oil and gas provinces. At that time the path to the development of fields in Eastern Siberia was already paved. The large-scale discoveries of a number of fields made here in the 70s-80s of the 20th century are only being developed now. The process of development itself is rather slow in view of a number of reasons. Create a problem of high cost value of oil extraction in the region. One of the major tasks is obtaining the maximum oil recovery factor while reducing the development costs. The carbonate layer lying within the Katangsky suite is low-permeability, and its inventories are categorised as hard to recover. Now, the object is at a stage of trial development,which foregrounds researches on selecting the effective methods of oil extraction.

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